The present invention relates to a method for oil recovery by tenside and/or emulsion flooding.
In the extraction of oil from oil-bearing reservoirs, it is generally possible only to recover a fraction of the originally present oil by means of primary extraction methods. In this procedure, the oil is brought to the earth's surface using the natural reservoir pressure. In secondary oil recovery, water is forced into one or several injection bore holes in the formation. The oil is pushed to one or several production wells and thereafter brought to the surface. This so-called water flooding as a secondary measure is relatively inexpensive and accordingly is frequently employed. However, in many cases it leads to only a minor increase in oil extraction from the deposit.
An effective displacement of the oil, which is more expensive but urgently required from the viewpoint of the economy because of the present scarcity of petroleum, is accomplished by tertiary measures. These are understood to include processes wherein the viscosity of the oil is reduced and/or the viscosity of the flooding water is increased and/or the interfacial tension between water and oil is lowered.
Most of these processes can be classified as solution or mixture flooding, thermal oil recovery methods, tenside or polymer flooding and/or as a combination of several of the aforementioned methods.
Thermal recovery methods include the injection of steam or hot water and/or take place as a subterranean combustion. Solution or mixture processes reside in injecting a gaseous or liquid solvent for the petroleum into the deposit.
Tenside flooding processes, depending on the tenside concentration and in some cases the type of tenside, and also on the additives used, are distinguished among tenside-supported water flooding, customary tenside flooding (low-tension flooding), micellar flooding, and emulsion flooding. All are based primarily on a strong lowering of the interfacial surface tension between oil and flooding water. However, in some instances, especially in the presence of relatively high tenside concentrations, water-in-oil dispersions are created having a markedly increased viscosity as compared with the oil. Thus, the tenside flooding step also aims at reduction in the mobility relationship whereby the degree of effectiveness of the oil displacement is raised. Pure polymer flooding is based predominantly on the last-described effect of a more favorable mobility ratio between oil and the pursuing flooding water.
Heretofore, organic sulfonates, such as alkyl, alkylaryl, or petroleum sulfonates, have been used primarily as oil-mobilizing tensides. However, these compounds exhibit a very low tolerance limit with respect to the salinity of the water in the deposit. Salt concentrations even as low as 1,000 ppm are considered problematical. The sensitivity of these tensides against alkaline earth ions is especially pronounced. In this respect, approximately 500 ppm is assumed to be the upper critical limit concentration (U.S. Pat. No. 4,100,228). In the presence of higher salt concentrations, precipitation products in the form of insoluble salts are formed when using these tensides. Thereby, on the one hand, material is lost for the desired effect in the oil-water interface; on the other hand, the precipitation products can lead to clogging of the formation. However, since many deposit waters possess substantially higher salinities (approximately half the North American light oil deposits exhibit salinities of around 100,000 ppm and higher, and there are many oil fields in North Germany having salinities of up to about 250,000 ppm, the content of dissolved alkaline earth ions being considerable in most cases), attempts have been made to find ways and means for exploiting the otherwise good oil-mobilizing properties of the organic sulfonates even for deposit systems having a relatively high salinity. In admixture with cosurfactants, such as alcohols or nonionic tensides, organic sulfonates also proved to be less sensitive to electrolyte.
In accordance with U.S. Pat. Nos. 4,016,932 and 3,811,504, it is possible to further increase the salinity tolerance of the organic sulfonates in admixture with other tensides.
In contrast to the group of organic sulfonates, the carboxymethylated alkyl or alkylaryl oxyethylates, just as the group of sulfated and sulfonated oxethylates (U.S. Pat. No. 4,293,428), show good compatibility even with extremely high-salinity deposit waters (250,000 ppm and higher). Alkaline earth ions possess no deleterious effect, even at concentrations of 30,000 ppm; on the contrary, their presence is even desirable, as demonstrated in German Pat. No. 3,033,927. Inasmuch as these tensides have a strongly oil-mobilizing effect, are stable under deposit conditions (as found by long-term experiments (cf. D. Balzer, Proceedings 2nd European Symposium Enhanced Oil Recovery, Paris 1982) and their production is simple and economical, they are very well suited for use in oil displacement in medium- and high-salinity deposit systems (10,000-250,000 ppm total salt content).
However, tenside flooding not only presents problems regarding a higher salinity of the reservoir, which has been overcome by the use of carboxymethylated oxethylates as the tensides, but a considerable problem also resides in tenside retention, which occurs in all cases. A considerable amount of injected tenside is lost by adsorption on the rock surface and by the so-called "phase trapping", meaning a trapping of liquid droplets of frequently high tenside content in the rock formation in front of pore constrictions. The two processes highly contribute toward tenside retention, which in the final analysis is really the total amount of tenside retained in the pore space during tensile flooding. Therefore, a prerequisite for an economical oil recovery by tertiary methods with the aid of tensides is that the tensides be highly effective and also that their retention be minor.
Several processes have been described in the literature wherein reduced tensile retention is achieved either by flooding with an additional active agent before use of the tenside solution or dispersion, or by admixing such active agent to the tenside solution or dispersion. Thus, lignin sulfonate proper (see U.S. Pat. No. 4,157,115) or lignin sulfonate in ethoxylated or propoxylated form (see U.S. Pat. No. 4,236,579) or in sulfomethylated form (see U.S. Pat. No. 4,269,270) lowers tenside adsorption on the rock surface. Maleates and succinates show similar effects as well (see U.S. Pat. No. 4,217,958). Also preliminary flooding with an aqueous LiCl solution is said to lower retention in case of tenside mixtures of petroleum sulfonate and ether sulfonate (see U.S. Pat. No. 4,281,714). However, these "sacrificial materials" act primarily as adsorption reducers, and the adsorption process is merely one of many processes contributing toward retention. Apparently, a strongly retention-reducing effect, at least in the case of low-salinity reservoir systems and with petroleum sulfonates as the tenside, is exerted by preliminarily flooded solutions of sodium carbonate or sodium orthosilicate, as demonstrated in several scientific publications [for example J. S. Falcone et al., JAOCS 59:826 A (1982)]. The injection of a strongly alkaline solution, however, also represents massive interference in the complicated equilibria of a deposit. Thus, use of these solutions also entails problems just as in connection with the process of alkali flooding.
Noticeable reduction in tenside retention is obtained by a modified tenside flooding method, using carboxymethylated oxethylates, by injecting the tenside in the form of an emulsion maximally adapted to the system (i.e., deposit water as the aqueous phase and deposit oil as the organic phase). If here the tenside or emulsifier is selected so that the phase inversion temperature of the system of crude oil/formation water/tenside (emulsifier) is at the deposit temperature or up to about 10.degree. C. thereabove, then this emulsion flooding method provides extensive reduction of the originally present oil without the formation of uncontrollably high pressure gradients (DOS No. 3,105,913 and U.S. Ser. No. 349,945, of Feb. 18, 1982, now U.S. Pat. No. 4,457,373). One disadvantage of this method, however, is that part of the oil injected as an emulsion is not extracted again by flooding. Compared with the amount of oil recoverable by the tertiary recovery method, this last amount is not inconsiderable. The high barrier, from a psychological and economic standpoint, facing an oil producer of reinjecting expensively extracted (or additionally purchased) oil, thus becomes even more insurmountable, especially in view of the considerable time span (years) between injection and production.